In a typical steam methane reformer operation for the production of hydrogen, natural gas is pretreated to remove sulfur. This is accomplished by hydrogenation of organic sulfur within a hydrotreater, which converts the organic sulfur to hydrogen sulfide, followed by hydrogen sulfide removal in a chemisorbent bed, utilizing, for example, a zinc oxide sorbent. The desulfurized feed is then mixed with steam and reformed in the steam methane reformer to produce a synthesis gas stream containing hydrogen and carbon monoxide. Such a synthesis gas stream can be further processed to produce hydrogen.
Steam methane reforming installations are relatively inflexible with respect to the variability in the amount of hydrogen produced and the type of feeds that can be processed and ultimately reformed. The amount of hydrogen produced is normally set by the plant design. For most plants the amount of hydrogen produced can only be decreased from normal production by cutting back on the flow rate of reactants and the firing rate. The feed to a steam methane reforming installation is normally natural gas. It is, however, desirable to process hydrocarbon streams containing hydrocarbons with more than two carbon atoms within a steam methane reformer. A common source for these hydrocarbon streams include by-product streams of refineries, chemical production facilities and metal producing operations. In many cases these streams have a high olefin content.
A variety of off-gas streams are produced in refineries from processes such as fluidic catalytic cracking, coking, catalytic reforming, hydrocracking and etc. Generally, all of these streams are used for fuel in furnaces and for making steam. Many refineries produce more of such fuel gas than they can economically use. Since these streams have a high hydrocarbon and generally, a moderate hydrogen content, they potentially could be reformed to produce synthesis gases that in turn are used to produce hydrogen. Hydrogen is a more valuable commodity than either fuel or steam. As indicated above, however, such feeds have a high olefin content and a high content of other hydrocarbons with more than two carbon atoms which makes treatment within the conventional hydrotreater problematical. Additionally, such streams tend to form carbon on the catalyst within the steam methane reformer causing eventual loss of activity of the reforming catalyst.
New hydrogen production facilities can be designed to utilize streams with high olefin content or high content of other hydrocarbons with more than two carbon atoms. In such facilities, the hydrotreater is designed to hydrogenate olefins to alkanes and a prereformer converts the other hydrocarbons with more than two carbon atoms to methane, carbon monoxide and hydrogen.
In an existing hydrogen production facility complicated modifications are necessary to allow utilization of streams with high olefin content and high content of other hydrocarbons with more than two carbon atoms. The existing hydrotreater will likely need to be replaced and a prereformer will be required to function in a manner set forth above. The new hydrotreater will likely require a larger reactor with a more expensive catalyst and possibly a means of diluting the hydrotreater feed, for example, by recycling part of the hydrotreater effluent. Adding a prereformer upstream of an existing steam methane reformer requires modifications to the existing primary reformer to add heat exchanging tubes for preheating the fuel feed to the prereformer and a prereformer reactor. The modifications to the existing reformer are costly and require shut down of the reformer for an extended period of time. The steam production will also decrease since some of the heat that was used to produce steam is now required for the prereformer. All these modifications are costly and in addition, the disruption to the reformer operation make such modifications to existing reformers very difficult to justify on an economic basis.
The hydrotreater even when replaced with one capable of processing olefins is nevertheless limited in the concentration of olefins that can be treated. The hydrogenation reaction is exothermic and excess olefins can cause an undesirable temperature rise. The hydrogenation catalyst is typically a nickel molybdenum or cobalt molybdenum based catalyst. The hydrogenation catalyst has an operating window from about 260° C. to about 415° C. Below 260° C. the catalytic reaction is very slow and above 415° C. the catalyst looses activity quickly. Due to reaction rate and such temperature limitations, space velocities that are greater than about 4000 hr−1 are too high for effective olefins reduction. Furthermore, each 1% by volume of olefins in the feed gas results in about a 40° C. temperature rise. Given the limited temperature operating window the usefulness of the hydrotreater has been limited to hydrocarbon feeds with less than about 5% olefins and low variability in olefin content. In any event, hydrotreaters are large, expensive devices when used to process any type of hydrocarbon feed that contain significant quantities of olefins.
The prereformer that would be used to treat higher order hydrocarbons also has operational limitations. Prereformers are generally adiabatic catalytic reactors that treat the incoming feed by converting the higher order hydrocarbons and some methane into hydrogen, carbon monoxide, water and carbon dioxide. In such manner, higher order hydrocarbons present within the feed are prevented from thermally cracking and producing a carbon deposit on the catalyst within the steam methane reformer. The prereformer catalyst is a nickel based catalyst that is more active and more expensive than the typical reformer catalyst and is also more sensitive to process upsets. For example overheating can result in activity loss so the feed conditions to the prereformer must be carefully controlled. The prereformer catalyst cannot accept olefin containing feed streams and it is typically positioned after the hydrotreater and sulfur removal unit. The prereforming catalyst has a shorter lifetime than the reforming catalyst and therefore requires additional plant shut downs for catalyst replacement.
Steam methane reformers can be designed to handle hydrocarbon feed containing alkanes with more than two carbon atoms with the use of an alkalized catalyst or with a high steam to carbon ratio. The alkali in such catalyst, however, can migrate and foul downstream equipment and the increased steam to carbon ratio reduces the plant energy efficiency.
It has been proposed to reform streams having a high olefin content by catalytic partial oxidation. In U.S. Patent Application 2004/0156778 a hydrogen-rich reformate is generated from a hydrocarbon feed stream comprising olefins and alkanes, for instance, liquefied propane gas. In the process disclosed in this patent application, the hydrocarbon feed stream comprising olefins and alkanes is pretreated by catalytic partial oxidation. The feed stream is fed to the catalytic partial oxidation reactor at a temperature of less than 300° C. and the temperature of the resultant gas stream is maintained below 400° C. These low temperatures are specifically required by the type of streams that are contemplated being processed in this patent, namely streams with a high propane content and relatively low olefin content. According to the patent at higher temperature, under the feed conditions defined in the patent, the propane in such streams will tend to decompose into olefins, propylene and ethylene, to add to the olefin content of such streams.
If refinery off-gases were treated by the process disclosed above, the olefin content would not be sufficiently reduced and the other hydrocarbons with two or more carbon atoms would still be problematical. In any event, with respect to existing steam methane reformers, the high olefin and other hydrocarbons with more than two carbon atoms present within such off-gases as have been discussed above will deactivate the reforming catalyst through coking. As such, the process disclosed in this patent does not present an alternative for treating such off-gases.
A catalytic partial oxidation process can be used to substantially convert such off-gases to a carbon monoxide and hydrogen containing synthesis gas. However such process will require significantly more oxygen, which is expensive, and if added as pretreatment system for a steam methane reformer, adds significantly in the cost of making hydrogen. For example, U.S. Pat. No. 5,720,901 discloses a process for producing a synthesis gas by partial oxidation of hydrocarbons having from 1 to 5 carbon atoms in which oxygen is added to the feed at an oxygen to carbon ratio that ranges between 0.3 to 0.8 and optionally steam at a steam to carbon ratio that ranges from 0.0 to 3.0. The process is conducted at a temperature of at least 950° C. In the process of this patent, sulfur containing compounds such as hydrogen sulfide, carbonyl sulfide, carbon disulfide, thiophenes, mercaptans and sulfides are a desirable component of the feed to be treated in that such compounds reduce the formation of ammonia and hydrogen cyanide. Such sulfur compounds will be converted into hydrogen sulfide which can be removed by a desulfurization unit, for example, one containing zinc oxide, to produce a synthesis gas product that can be supplied to a sulfur-sensitive application such as Fischer-Tropsch.
As will be discussed, the present invention provides a method of steam methane reforming to produce a synthesis gas utilizing a dual mode catalytic reactor, which is defined here as a catalytic reactor that with the same catalyst can function in an oxygen consuming catalytic oxidative mode of operation to pre-treat hydrocarbon containing feeds to the steam methane reformer to increase hydrogen output or can be used in a catalytic hydrogenation mode of operation with no consumption of oxygen to pre-treat feeds by converting olefins into saturated hydrocarbons. In both modes of operation, sulfur compounds will be chemically reduced to hydrogen sulfide so as to not require the use of a conventional hydrotreater in at least new installations. Such method has particular applicability to the treatment of feeds of refinery off-gases and like compositions containing objectionable levels of hydrocarbons so that such feed can be used with a conventional steam methane reformer designed for natural gas feed.